Swellable materials have been used in a range of oil and gas exploration and production equipment. Most notably, swellable materials have been used in wellbore packers for creating a seal in an annular space between a tubing and a surrounding wall of a cased hole or openhole well. A typical swellable packer includes a mantle of swellable elastomeric material formed around a tubular body. The swellable elastomer is selected to increase in volume on exposure to at least one triggering fluid, which may be hydrocarbon fluid or an aqueous fluid or brine. The packer is run to a downhole location in its unexpanded, unswollen state where it is exposed to a wellbore fluid and caused to swell. The design, dimensions, and swelling characteristics are selected such that the swellable mantle creates a fluid seal in the annulus, thereby isolating one wellbore section from another. Swellable packers have several advantages over conventional packers, including passive actuation, simplicity of construction, and robustness in long term isolation applications. Examples of swellable packers and suitable materials are described in GB 2411918.
The swell characteristics of the packer are critical to proper performance of the packer. Important swell characteristics include the swell rate, the time taken for the outer surface of the mantle to reach and contact the exterior surface (which may be referred to generally as “contact time”) and the time taken to reach the point of maximum internal pressure exerted by the packer on the surrounding surface (which may be referred to generally as “pack-off time”). The swell characteristics are dependent on various factors including the materials used, the dimensions and design of the tool, the wellbore conditions (including temperature and pressure), and the fluid or fluids to which the tool is exposed.
It is known in the art to carry out tests on swellable packers by placing a representative sample of the packer in a fluid. A typical sample packer section is shown in FIG. 1, generally depicted at 10. A swellable mantle 12 is formed on a pipe or mandrel 14 according to conventional manufacturing techniques and has a known outer diameter and thus a known mantle thickness. The packer section 10 is formed by cutting a short length, for example 8 to 15 cm, through the mantle 12 and the pipe 14. The sample packer section 10 is placed in a fluid bath (not shown), which contains a hydrocarbon or aqueous fluid or brine used for the test. The fluid bath is located inside an oven, which can be heated to typical wellbore temperatures. For example, the oven may be operable to heat the fluid and packer section 10 to temperature of around 80° C. to 150° C. The packer section 10 is left in the fluid bath for the duration of the test (which may be several days). At regular intervals during the test, the oven is opened, the packer section is removed, and the outer diameter is measured manually using a calliper gauge. The measurement data for such packer sections 10 are generally considered by the industry to be representative of the swell times of a complete tool of the same radial dimensions and configuration in a wellbore environment.
FIG. 2 is a plot of thickness change, expressed as a percentage of the original thickness, versus exposure time of a sample packer section 10 with an initial outer diameter of 5.75 inches (approximately 146 mm) on a base pipe having outer diameter of 4.5 inches (around 114 mm). The packer section 10 of this example had a swellable mantle 12 formed from ethylene propylene diene M-class rubber (EPDM) rubber and was exposed to Clairsol® (a hydrocarbon fluid) at 90° C. The data show that the time taken for the sample section to swell to its maximum volume (with a percentage thickness increase of around 80%) is around 600 hours or 25 days.
A packer will be deployed in and sealing with a wellbore of known inner diameter. For example, the packer 10 for the test data of FIG.2 is designed for sealing with a bore of inner diameter in the range of 6 to 6.8 inches (about 152.4 mm to 172.7 mm). The measurements of particular interest are the time taken for a swellable mantle to increase in outer diameter to contact a surrounding surface of a wellbore of a particular inner diameter (the “contact time”) and the time taken for the swellable mantle to exert its maximum internal pressure against a sealing surface of a particular inner diameter (the “pack-off time”). In the example of FIG.2, the packer has a contact time of 60 hours with a 6.125 inch (about 155.6 mm) wellbore.
Performing such tests on packer sections requires an oven and a suitable fluid chamber, which typically lacks portability and takes up valuable space at an exploration or production installation. Carrying out the tests is labour intensive, and may be hazardous due to the nature of the fluids used and the elevated temperatures. Physical handling of the sample sections may be difficult or unsafe when the packer sections have been exposed to fluid, particularly at high temperatures. Measurement of the outer diameter is prone to error, particularly because the swellable material is soft and may be deformed by the callipers. Multiple personnel may be required to measure the outer diameter at different measurement times, and each individual may take a measurement by a slightly different technique, introducing further uncertainty into the measurement data. The long swelling times of the sample packer sections are inconvenient for rapid measurement of swell characteristics. The long test times also increase the likelihood of multiple personnel being used to measure the outer diameter, and therefore increase the likelihood of inconsistent measurements. Long test times limit the repeatability of the tests, and reduce the practicability of tests being carried out for multiple fluid samples. These factors combine to reduce the quality of the available measurement data.
With packer sample section 10 of the prior art, the ends of the swellable member 12 are exposed to the test fluid, which increases the surface area-to-volume ratio at each end of the section 10, relative to the surface area-to-volume ratio at its axial midpoint. This means that the swelling rate of the swellable member at the end of the sample section 10 is likely to be greater than the swelling rate at its axial midpoint, causing non-uniform swelling which can have an adverse effect on the accuracy of the measurements of the outer diameter.
The industry tends to make assumptions about the swell characteristics of swellable materials in different fluids. For example, a simplified model of volume increase of swellable elastomers assumes that the swell rate of a swellable material depends primarily on the viscosity of the fluid to which it has exposed. Accordingly, a sample packer section 10 may be tested in a fluid of low viscosity (for example 1 cP), with measurements of percentage change in thickness over time being made. Measurements may also be made for an identical sample packer section in a higher viscosity of fluid (for example 100 cP or 100 mPa). In order to predict the swell characteristics of a packer section in a given wellbore fluid sample with a different viscosity, the measurement data will be interpolated or extrapolated rather than repeating the tests in the wellbore fluid sample.
Additionally, in some simplified models, the pack-off time for a particular inner diameter is assumed to be constant multiplier of the contact time. This simplified model is flawed, because it does not account for different swelling end points of a swellable material in different fluid samples. For example, a packer sample section exposed to one hydrocarbon fluid with 1 cP viscosity might have a maximum swelling extent of, for example 75% of the original mantle thickness, whereas the swelling end point of an identical tool sample in a different hydrocarbon fluid, also having a viscosity of 1 cP, may have a swelling end point of 80% of the original thickness of the mantle. FIG.3 is a plot of swelling profile of two identical sample sections in different hydrocarbon-based fluids with the same viscosity (1.5 cP). The plot shows that the swell characteristics of the sample in Fluid 1 (which was the special kerosine Clairsol 350 MHF™) are different from the swell characteristics of the sample in Fluid 2 (which was a gas oil) despite the test fluids having the same fluid viscosity. Different swelling end points have an effect on the contact time and pack-off time, which is not accounted for in a model which relies on viscosity effects only. This illustrates that it would be advantageous to account for fluid types when assessing swell characteristics.
It is amongst the aims and the objects of the invention to provide methods, testing apparatus, and test pieces which overcome or mitigate the drawbacks of conventional testing procedures and apparatus.
Further aims and objects of the invention will become apparent from the following description.